|Publication number||US6331775 B1|
|Application number||US 09/396,286|
|Publication date||Dec 18, 2001|
|Filing date||Sep 15, 1999|
|Priority date||Sep 15, 1999|
|Publication number||09396286, 396286, US 6331775 B1, US 6331775B1, US-B1-6331775, US6331775 B1, US6331775B1|
|Inventors||Holger F. Thern, Songhua Chen|
|Original Assignee||Baker Hughes Incorporated|
|Export Citation||BiBTeX, EndNote, RefMan|
|Patent Citations (12), Non-Patent Citations (3), Referenced by (48), Classifications (10), Legal Events (6)|
|External Links: USPTO, USPTO Assignment, Espacenet|
The invention is in the field of determination of petrophysical properties of a partially gas filled medium using data from a Nuclear Magnetic Resonance (NMR) tool and a density tool. More specifically, the method is used to determine porosity, gas saturation and in situ gas density in a hydrocarbon reservoir.
A variety of techniques have been utilized in determining the presence and in estimating quantities of hydrocarbons (oil and gas) in earth formations. These methods are designed to determine formation parameters, including among other things, porosity, fluid content and permeability of the rock formation surrounding the wellbore drilled for recovering hydrocarbon. Typically, the tools designed to provide the desired information are used to log the wellbore. Much of the logging is done after the well bores have been drilled. More recently, wellbores have been logged while drilling of the wellbores, which is referred to as measurement-while-drilling (“MWD”) or logging-while-drilling (“LWD”). Measurements have also been made when tripping a drillstring out of a wellbore: this is called measurement-while-tripping (“MWT”).
One recently evolving technique involves utilizing Nuclear Magnetic Resonance (NMR) logging tools and methods for determining, among other things porosity, hydrocarbon saturation and permeability of the rock formations. The NMR logging tools are utilized to excite the nuclei of the of the fluids in the geological formations in the vicinity of the wellbore so that certain parameters such as spin density, longitudinal relaxation time (generally referred to in the art as “T1”) and transverse relaxation time (generally referred to as “T2”) of the geological formations can be estimated. From such measurements, porosity, permeability and hydrocarbon saturation are determined, which provides valuable information about the make-up of the geological formations and the amount of extractable hydrocarbons.
A typical NMR tool generates a static magnetic field B0 in the vicinity of the wellbore, and an oscillating field B1 in a direction perpendicular to B0. This oscillating field is usually applied in the form of short duration pulses. The purpose of the B0 field is to polarize the magnetic moments of nucleii parallel to the static field and the purpose of the B1 field is to rotate the magnetic moments by an angle θ controlled by the width tp and the amplitude B1 of the oscillating pulse. With the variation of the number of pulses, pulse duration and pulse intervals, various pulse sequences can be designed to manipulate the magnetic moment, so that different aspects of the NMR properties can be obtained. For NMR logging, the most common sequence is the Carr-Purcell-Meiboom-Gill (“CPMG”) sequence that can be expressed as
After being tipped by 90°, the magnetic moment precesses around the static field at a particular frequency known as the Larmor frequency ω0, given by ω0=γB0, where B0 is the field strength of the static magnetic field and γ is the gyromagnetic ratio. At the same time, the single magnetic moments return to the equilibrium direction (i.e., aligned with the static field) according to a decay time known as the “spin-lattice relaxation time” or T1. Inhomogeneities of the B0 field result in dephasing of the magnetic moments and to remedy this, a 180° pulse is included in the sequence to refocus the magnetic moments. This gives a sequence of n echo signals.
U.S. Pat. No. 5,023,551 issued to Kleinberg discloses an NMR pulse sequence that has an NMR pulse sequence for use in the borehole environment which combines a modified fast inversion recovery (FIR) pulse sequence with a series of more than ten, and typically hundreds, of CPMG pulses according to
where j−1,2, . . . J and J is the number of echoes collected in a single Carr-Purcell-Meiboom-Gill (CPMG) sequence, where i=1, . . . I and I is the number of waiting times used in the pulse sequence, where Wi are the recovery times, TWi are the wait times before a CPMG sequence, and where t is the spacing between the alternating 180° pulses and the echo signals.
Proton NMR measurement is typically performed for logging since hydrogen is abundant in reservoir fluids. T2 is very short in solids, but relatively long in liquids and gases, so that the NMR signal from the solid rock decays quickly and only the signal from fluids in the rock pores in the region of interest is seen. This signal may arise from hydrogen in hydrocarbon or water within the pores of the formation. The local environment of the hydrogen influences the measured T2 or “spin-spin” relaxation. For example, capillary bound fluid has a shorter T2 than fluid in the center of a pore, the so-called “free fluid.” In this way, the NMR tool can be used advantageously to distinguish between producible fluid and non-producible fluid.
The NMR echo signals provide information about fluid and rock properties. Depending upon the goal of the investigation, various NMR measurement techniques can be used to obtain different petrophysical properties (e.g., partial and total porosities) or to discern multiphase fluids for hydrocarbon typing purposes. The different NMR acquisition techniques are characterized by differences in pulse timing sequences as well as repetition times between measurements. In addition, in wireline applications, multiple runs of NMR acquisition sequences with different parameters can be combined to enhance the analysis of the desired petrophysical information. However, in measurement-while-drilling applications or in measurement-while-tripping applications, it is not possible to make multiple runs, so that all the desired information must be obtained at one time while the borehole is being drilled or tripped.
Several methods to identify and quantify gas reservoirs have been employed during the last few years utilizing the effect of different wait times on the measured NMR signal. Depending upon the fluid properties, the wait time (TW) determines the amount of the polarized medium that contributes to the measured signal. For example, Akkurt et.al. disclose a Differential Spectrum Method (DSM) based upon this effect in their paper “NMR Logging of Natural Gas Reservoirs” presented at the 36th Annual Meeting of the Society of Professional and Well Log Analysts (SPWLA) in 1995. Another related technique is the Time Domain Analysis (TDA) presented in the 1995 Society of Petroleum Engineers meeting by Prammer et. al. in a paper entitled “Lithology-Independent Gas Detection by Gradient NMR Logging.” These techniques require the calculation of differential echo signals or differential T2 spectra that are derived from the echo trains by an inversion. The differential quantities are derived from two echo train data acquired with different wait times by subtracting either the echo train data or their T2 spectra. As would be known to those versed in the art, this subtraction of one noisy signal from a second noisy signal leads to a reduction in signal-to-noise ratio. This, coupled with the low hydrogen density of a gaseous hydrocarbon, is a major problem in accurately estimating reservoir properties.
European Patent Application 0 871 045 of Freedman discloses a method in which an oscillating magnetic field is produced according to the Carr-Purcell-Meiboom-Gill (CPMG) sequence to induce NMR echo signals. The spin echo signals are separated into a first set and a second set wherein the first set comprises the early-time echo signals and the second set comprises the remaining echo signals. The second set of echo signals are subdivided into a plurality of groups and a window sum value is generated for each group of the second set, producing a plurality of window sums.
In formations having a gas saturation, the porosity as determined by a conventional density tool needs to be corrected because the presence of the gas phase causes the porosity to be overestimated. On the other hand, an NMR-derived porosity obtained using a CPMG sequence wherein TW is sufficiently long to substantially polarize all the formation fluid in the sensitive volume underestimates the true porosity. Solving a system of two equations, the true porosity is then obtained as a function of the NMR derived porosity, the density derived porosity, and a hydrogen index of the liquid phase HIl in the flushed zone at reservoir conditions.
where PORZ is the porosity derived from the density measurement, TPOR is the NMR-derived porosity. The value of w depends, among other factors, on the hydrogen index of the gas phase HIg, the CPMG pulse sequence TW and the longitudinal NMR relaxation time of the gas T1,g. Freedman suggests that a quick estimate of the porosity can be obtained by using a value of 0.6 for w, and using a value for HIl of 1.0, so that the true porosity becomes a weighted average of the density derived porosity and NMR derived porosity.
There is a need for a method of obtaining the porosity and gas saturation of a reservoir more accurately and without making the approximation of using a constant weighting factor w. There is also a need to characterize the gas phase by the spin-lattice relaxation time of the gas T1g, the hydrogen index of the gas HIg, and density of the gas ρg in order to derive the gas saturation Sg,xo of the reservoir. The present invention satisfies this need.
The invention is a method for acquiring nuclear magnetic resonance measurements of a porous medium and determining the total porosity and gas saturation of a partially gas filled medium. The method includes inducing an external static magnetic field in the material, and applying a radio frequency pulse to tip the spins by 90°. The resulting precession of the spins is detected by a receiver coil. A refocusing pulse having a spin tip angle substantially less than 180° is applied. Measurements are made with two different “wait times” in the NMR pulse sequence to give two different apparent porosities of the medium. When combined with a density measurement using a conventional density logging tool, the gas saturation and porosity of a medium can be determined with higher accuracy than in prior art methods without making the assumptions used therein. The method also includes estimation of certain properties of the gas.
FIG. 1 illustrates an embodiment of the invention in which determination of the parameters of interest of a formation is done at a single depth of a gas reservoir.
FIG. 2 illustrates an embodiment of the invention in which determination of the parameters of interest of a formation is done using data from a plurality of depths within a single, connected gas reservoir.
A typical nuclear magnetic resonance (“NMR”) instrument which can make measurements according to this invention is described, for example, in U.S. Pat. No. 5,585,720 issued to Edwards, the contents of which are fully incorporated herein by reference. The instrument described in the Edwards ′720 patent includes a permanent magnet for inducing a static magnetic field within the medium to be analyzed. In particular, the medium to be analyzed can include earth formations surrounding a wellbore. The instrument in the Edwards ′720 patent includes an antenna coil which can be wound around the magnet, circuitry for applying pulses of radio-frequency (RF) power to the antenna coil, and circuitry for detecting voltages induced in the antenna coil as a result of nuclear magnetic resonance phenomena, particularly that of hydrogen nuclei present in the earth formations.
As is known in the art, the RF pulses applied to the antenna coil of NMR apparatus such as the one in the Edwards ′720 patent typically include an initial RF pulse having a duration and amplitude which reorients the nuclear spin axes of the hydrogen nuclei in the earth formations so that they become substantially perpendicular to the direction of the static magnetic field induced by the magnet. This first RF pulse induces an angular deflection of about 90 degrees in the spin axes of the hydrogen nuclei. Later in the measurement cycle known in the art, a sequence of additional RF pulses (referred to as “refocusing pulses”), each having a duration and amplitude selected to reorient the extant nuclear spin axes by 180 degrees, is applied to the antenna coil. In between refocusing pulses, the antenna coil is connected to a receiver circuit to detect voltages induced in the antenna coil as the nuclear spin axes “rephase”, an event called the pulse-echo or spin echo. The combination of tipping pulses and refocusing pulses is known as a Carr-Purcell-Meiboom-Gill (CPMG) sequence. As is understood by those skilled in the art, the amplitude of the induced voltages from spin rephasing (pulse-echo voltages) decreases after each successive refocusing pulse applied to the antenna coil. The rate at which the amplitude of the successive pulse-echo voltages decays is related to properties of the earth formations such as fractional volume of pore space and the bulk volume of mobile fluids filling the pore space, as is known in the art.
In co-pending U.S. application Ser. No. 09/151,871, having the same assignee as the present application and the contents of which are incorporated herein by reference, it has been disclosed that the refocusing pulses should preferably have a duration and amplitude selected to cause the nuclear spin axes to reorient by an angular deflection different from 180 degrees, and between 100° and 135°. With such a refocusing pulse, the power requirements are reduced and the signal to noise ratio of the echos is improved.
Accordingly, the RF field of the present invention includes a pulse sequence
where TW is a wait time, 90±x represent tipping pulses for tipping the nuclear spins at an angle substantially equal to ninety degrees to cause precession thereof, t is the spacing between the alternating refocusing pulse and the echo signal, X is an optimized refocusing pulse, and j=1,2, . . . J, where J is the number of echoes collected in a single sequence of pulses.
The present invention is a method for evaluating the petrophysical properties of a gas reservoir including one gas phase and one liquid phase. The method combines the apparent porosities TPORA and TPORB of a dual wait time NMR measurement obtained using wait times of TWA and TWB respectively with the apparent porosity PORZ of a density measurement and obtains the true porosity Φ of the gas zone, the gas saturation Sg,xo in the gas zone, the gas density ρg in the gas zone, the hydrogen index HIg of the gas zone, and, the spin-lattice relaxation time of the gas T1g. A depth-dependent formation temperature is obtained during the acquisition of the NMR or density data, while the matrix density ρma is obtained from external information, such as sample measurements or interpretations of other logs.
In a two-phase system with one gas and one liquid phase, the apparent total porosity TPOR as measured by an NMR tool is given by
where the first term describes the contribution of the gas phase and the second term the contribution of the liquid phase. Φ here denotes the porosity of the formation, HIg and HIl are the hydrogen indices of the gas phase and the liquid phase respectively, Sg,xo is the gas saturation, and Pg and Pl are the polarizations of the gas and liquid phases respectively produced by the NMR signal. These are related to the wait time TW of the NMR signal by
As would be known to those versed in the art, equation (2) is valid only if the apparent porosity is determined using a long CPMG sequence to obtain the T2 distribution. A number of simplifications may be made for most liquids without detracting from the scope of the invention. For an aqueous phase liquid and for most hydrocarbons, the value of HIl is close to 1. The polarization effects of liquids Pl is negligible if the spin lattice relaxation time T1l is much smaller than the wait time TW. Typically, TW ranges from 1 to several seconds, whereas a typical aqueous phase liquid has a T1l in the range of 1 to several hundred milliseconds in a two-phase system. Thus, Pl can usually be taken to be equal to 1 in a two-phase system.
The present invention determines the apparent porosity from NMR measurements using a pulse sequence having two different wait times TWA and TWB. This is done by using an RF field including a first pulse sequence TWA−90−(tcp−X−tcp−echo)j and a second pulse sequence TWB−90−(tcp−X−tcp−echo)j, wherein TWA is a first waiting time and TWB is a second wait time different from the first wait time. In a preferred embodiment of the invention, the dual wait time echo signals are obtained in a single pass of the logging instrument. In an alternate embodiment of the invention when measurements are made using a wireline device, the echo signals for the first and second wait times may be obtained in two different passes of the logging instrument.
Under these assumptions, the apparent porosities for the dual wait time NMR device may be written as
In one embodiment of the invention, the hydrogen index of the liquid phase HIl and the polarization of the liquid phase Pl are taken to be one. However, if the formation includes oleic phase liquids or a mixture of oleic and aqueous liquids, those versed in the art would recognize the that these two quantities cannot be taken as equal to one. An alternate embodiment of the invention uses externally derived values for HIl and Pl.
The wait times TWA and TWB are chosen so that they substantially polarize the liquid, i.e., Pl(TWA)≈Pl(TWB)≈1, while the polarization of the gas in the formation is substantially different for TWA and TWB.
The density ρb measured by a density tool is given by
Using the relation
the apparent total porosity measured by a density tool for a two phase fluid system can be written as
In the present invention, the matrix density ρma is obtained from other measurements, such as interpreted logs or core plugs and is, in general, constant over the particular reservoir being investigated. For example, ρma is 2.65 g/cc for sandstones while values for other common reservoir rocks such as limestones and dolomites would be known to those versed in the art. In one embodiment of the invention, the liquid density ρl is approximately 1.0 g/cc for aqueous liquids while in an alternate embodiment of the invention, for an oleic reservoir liquid, the density a lower density, e.g., 0.8-0.9 g/cc, is used.
In the present invention, the temperature of the reservoir is determined by a suitable temperature sensor. Based on measurement and theory, the spin-lattice relaxation time of the gas T1g is related to the temperature and density of the gas by an equation of the form
where B is a constant for a single gas phase with constant volumetrics and C has a theoretical value of 1.5. In equation (1), TK is the temperature of the gas in degrees Kelvin, i.e., the absolute temperature. Experimental data, such as that published by Gerritsma and Trappeniers may be used to determine empirical values for B and C.
Based on the definition of the Hydrogen Index, there is a linear relationship between the gas hydrogen index and the gas density
For every known hydrocarbon or known mixture of hydrocarbons, the factor A can be calculated exactly. Gaymard and Poupon in their paper “Response of Neutron and Formation Density Logs in Hydrocarbon Bearing Formations” found an approximate value of A=2.2 for hydrocarbons with density less than 0.25 g/cc in the gaseous phase. For pure methane, the exact value of A is 2.25.
Equations 5, 6, 9, 10 and 11 are five equations in five unknowns Φ, Sg,xo, ρg, HIg and T1g. They may be solved using the assumptions discussed above for the five unknowns.
Equations 5 and 6 show that TPORA and TPORB are functions of four variables
Substituting from equations (10) and (11) reduces (12) and (13) to equations of the form
Equation (9) is already in the form
The system of five equations in five unknowns is now reduced to three equations in three unknowns. These may be solved numerically using known methods to obtain Φ, Sg,xo and ρg. By back substituting the value of ρg in equations (10) and (11), HIg and T1g may be determined.
A preferred embodiment of the present invention involves the following steps:
1. Obtain NMR measurements using at least two different wait times TWA and TWB.
2. Analyze the results of step (1) using known techniques to obtain apparent total porosities TPORA and TPORB.
3. Determine an apparent total porosity PORZ from density measurements.
4. Substitute from equations (10) and (11) in equations (5) and (6) to give equations of the form (14) and (15).
5. Using the density measurement and the derived apparent total porosity, solve equations (14)-(16) to determine the true porosity, the gas saturation and the gas density. This may be done numerically using known methods.
6. Substitute the determined gas density from step 5 into equation (10) and (11) to get the spin-lattice relaxation time of the gas T1g and the hydrogen index of the gas.
Steps 1-6 are schematically represented in FIG. 1. 102, 104 and 106 are the representations of equations (12), (13) and (16) Substituting firm equations (9) and (11) (Box 108), equations (14) and (15) are obtained (boxes 110, 112). Solution of equations (16), (14) and (15) gives the gas density ρg, the true porosity Φ and the gas saturation Sg,xo, (box 114). Using the information in 114 in equations (9) and (11) (box 108) gives the hydrogen index of the gas and the spin-lattice relaxation time of the gas T1g (116).
Those versed in the art would recognize that solution of five equations for five unknowns using noisy measurements may occasionally lead to numerical instabilities. Accordingly, in such cases, an alternate embodiment of the invention using multiple measurements within a single gas reservoir may be used.
This method assumes that measurements are made at a plurality of depths within a single connected gas reservoir with substantially uniform gas composition. Turning now to FIG. 2, the observations at the plurality of depths are processed separately to give three different apparent porosities. These values are then averaged over the plurality of depths to give three averaged apparent porosities 202, 204 and 206. Equations (9) and (11) (box 208) are used to express the average apparent NMR porosities as functions of porosity, gas saturation and gas density (210 and 212). These functional relations are combined with the averaged density-derived apparent porosity to give an average gas density at 214 and average values of the hydrogen index Hlg and spin-lattice relaxation time of the gas T1g, (Box 216).
A plurality of temperature measurements are made in the reservoir to give a temperature profile 218. As would be known to those versed in the art, pressure, volume and temperature of a gas are related by an equation of state. One such equation of state is that developed by van der Waal:
where p is the pressure, V is the volume, n is the number of moles of gas, R is the gas constant, T is the absolute temperature, and a and b are constants depending upon the type of gas. The values for p, V, n and R are well-defined and values for a and b may be found in tables. Using this, or any other suitable equation of state for a gas, the measured temperature of the reservoir as a function of depth, and a depth dependent pressure gradient, the gas density as a function of depth is determined from the average gas density. The depth dependent pressure gradient, as would be known to those versed in the art, is approximately 0.433 psi/ft for normally pressured formations. From this density profile, a depth profile of the hydrogen index and the gas relaxation time may be obtained (box 220).
At this point, the processing may be performed at individual depths using the information in 220 with the three apparent porosities 222, 224, 226. These may be expressed as functions of two variables (Box 228, 230, 232) ( the true porosity and the gas saturation) as an overdetermined set of equations and solved by known methods to give the porosity and gas saturation (Box 234) at each depth. One advantage of using the method of FIG. 2 is that averaged values of the apparent porosities are used in the determination of the average gas density, the average hydrogen index of the gas, and the average spin-lattice relaxation time of the gas, thereby avoiding possible numerical instability that could arise in the method of FIG. 1 and increasing the accuracy of the estimated properties.
Those skilled in the art will devise other embodiments of this invention which do not depart from the spirit of the invention as disclosed herein. Accordingly, the invention should be limited in scope only by the attached claims.
|Cited Patent||Filing date||Publication date||Applicant||Title|
|US5023551||Dec 19, 1989||Jun 11, 1991||Schlumberger-Doll Research||Nuclear magnetic resonance pulse sequences for use with borehole logging tools|
|US5517115||Dec 16, 1993||May 14, 1996||Numar Corporation||Efficient processing of NMR echo trains|
|US5585720||Oct 23, 1995||Dec 17, 1996||Western Atlas International, Inc.||Signal processing method for multiexponentially decaying signals and application to nuclear magnetic resonance well logging tools|
|US5680043 *||Mar 23, 1995||Oct 21, 1997||Schlumberger Technology Corporation||Nuclear magnetic resonance technique for determining gas effect with borehole logging tools|
|US5796252 *||Jan 15, 1997||Aug 18, 1998||Schlumberger Technology Corporation||Nuclear magnetic resonance borehole logging apparatus and method for ascertaining a volume of hydrocarbons independent of a diffusion coefficient|
|US6005389 *||Mar 13, 1997||Dec 21, 1999||Numar Corporation||Pulse sequences and interpretation techniques for NMR measurements|
|US6032101 *||Apr 8, 1998||Feb 29, 2000||Schlumberger Technology Corporation||Methods for evaluating formations using NMR and other logs|
|US6051973 *||Dec 23, 1997||Apr 18, 2000||Numar Corporation||Method for formation evaluation while drilling|
|US6140817 *||May 26, 1998||Oct 31, 2000||Schlumberger Technology Corporation||Magnetic resonance well logging method and apparatus|
|US6163153 *||Sep 11, 1998||Dec 19, 2000||Western Atlas International, Inc.||Nuclear magnetic resonance pulse sequence for optimizing instrument electrical power usage|
|EP0871045A2||Mar 16, 1998||Oct 14, 1998||Schlumberger Holdings Limited||Method and apparatus for measuring total nuclear magnetic resonance porosity|
|WO1998029639A1||Dec 29, 1997||Jul 9, 1998||Numar Corporation||Method for formation evaluation while drilling|
|1||Lithology-Independent Gas Detection by Gradient-NMR Logging; SPE 30562; M.G. Prammer, et al. NUMAR Corporation; pp 1-12.|
|2||NMR Logging of Natural Gas Reservoirs, R. Akkurt, et al.; SPWLA 36th Annual Logging Symposium, Jun. 26-29, 1995; pp. 1-12.|
|3||Response of Neutron and Formation Density Logs In Hydrocarbon Bearing Formations; R. Gaymard and A. Poupon; The Log Analyst, pp. 3-12.|
|Citing Patent||Filing date||Publication date||Applicant||Title|
|US6466013 *||Apr 18, 2000||Oct 15, 2002||Baker Hughes Incorporated||Nuclear magnetic resonance measurements in well logging using an optimized rephasing pulse sequence|
|US6727696||Aug 13, 2001||Apr 27, 2004||Baker Hughes Incorporated||Downhole NMR processing|
|US6833698 *||May 15, 2002||Dec 21, 2004||Chevrontexaco U.S.A. Inc.||Methods of decoupling diffusion effects from relaxation times to determine properties of porous media containing fluids|
|US6859033||Aug 28, 2002||Feb 22, 2005||Schlumberger Technology Corporation||Method for magnetic resonance fluid characterization|
|US6882147 *||Aug 27, 2003||Apr 19, 2005||Baker Hughes Incorporated||NMR detection of small amount of fast transversal relaxation component in mixtures|
|US6972564||Nov 5, 2002||Dec 6, 2005||Baker Hughes Incorporated||Objective oriented methods for NMR log acquisitions for estimating earth formation and fluid properties|
|US6977499||May 21, 2003||Dec 20, 2005||Baker Hughes Incorporated||Formation-based interpretation of NMR data for carbonate reservoirs|
|US6984980 *||Apr 26, 2002||Jan 10, 2006||Baker Hughes Incorporated||Method and apparatus for NMR sensor with loop-gap resonator|
|US7193414||Apr 21, 2004||Mar 20, 2007||Baker Hughes Incorporated||Downhole NMR processing|
|US7266509||May 16, 2006||Sep 4, 2007||Eric Koenig||System and method for combining interactive game with infomercial|
|US7298142||Jun 27, 2005||Nov 20, 2007||Baker Hughes Incorporated||Method and apparatus for reservoir fluid characterization in nuclear magnetic resonance logging|
|US7336071 *||Aug 26, 2005||Feb 26, 2008||Baker Hughes Incorporated||Enhancement of NMR vertical resolution using walsh function based inversion|
|US7358725||May 16, 2006||Apr 15, 2008||Baker Hughes Incorporated||Correction of NMR artifacts due to axial motion and spin-lattice relaxation|
|US7502692||Dec 7, 2006||Mar 10, 2009||Baker Hughes Incorporated||Method and computer program product for estimating true intrinsic relaxation time and internal gradient from multigradient NMR logging|
|US7565246 *||Jul 21, 2009||Baker Hughes Incorporated||Determination of gas saturation radial profile from multi-frequency NMR data|
|US7705592||Feb 1, 2008||Apr 27, 2010||Baker Hughes Incorporated||Two dimensional T1/T2APP-T2APP processing of multi-gradient NMR data|
|US7804297 *||Sep 28, 2010||Baker Hughes Incorporated||Methodology for interpretation and analysis of NMR distributions|
|US7812602||Oct 12, 2010||Baker Hughes Incorporated||Multiple echo train inversion|
|US7825661||Aug 28, 2008||Nov 2, 2010||Baker Hughes Incorporated||Method and apparatus for NMR saturation|
|US8131469||Oct 3, 2008||Mar 6, 2012||Baker Hughes Incorporated||Data acquisition and processing for invasion profile and gas zone analysis with NMR dual or multiple interecho spacing time logs|
|US8330460||Jul 13, 2010||Dec 11, 2012||Baker Hughes Incorporated||Method and apparatus for determining multiscale similarity between NMR measurements and a reference well log|
|US8836328||Feb 1, 2011||Sep 16, 2014||Baker Hughes Incorporated||Acoustic excitation with NMR pulse|
|US8866475 *||Nov 4, 2011||Oct 21, 2014||Baker Hughes Incorporated||Method for correcting NMR and nuclear logs in formate mud filtrate invaded formations|
|US9335195||Feb 16, 2011||May 10, 2016||Baker Hughes Incorporated||Multiphase meter to provide data for production management|
|US20030107374 *||Nov 5, 2002||Jun 12, 2003||Baker Hughes Incorporated||Objective oriented methods for NMR log acquisitions for estimating earth formation and fluid properties|
|US20030214287 *||May 15, 2002||Nov 20, 2003||Boqin Sun||Methods of decoupling diffusion effects from relaxation times to determine properties of porous media containing fluids and multi-dimensional representation of those properties|
|US20030231017 *||May 21, 2003||Dec 18, 2003||Baker Hughes Incorporated||Formation-based interpretation of NMR data for carbonate reservoirs|
|US20040041562 *||Aug 28, 2002||Mar 4, 2004||Peter Speier||Method for magnetic resonance fluid characterization|
|US20040196038 *||Apr 21, 2004||Oct 7, 2004||Baker Hughes Incorporated||Downhole NMR processing|
|US20040257076 *||Aug 27, 2003||Dec 23, 2004||Baker Hughes Incorporated||NMR detection of small amount of fast transversal relaxation component in mixtures|
|US20050257610 *||Jul 12, 2005||Nov 24, 2005||Baker Hughes Incorporated||Automatic adjustment of NMR pulse sequence to optimize SNR based on real time analysis|
|US20060158184 *||Jan 18, 2005||Jul 20, 2006||Baker Hughes Incorporated||Multiple echo train inversion|
|US20070047117 *||Aug 26, 2005||Mar 1, 2007||Baker Hughes Incorporated||Enhancement of NMR vertical resolution using walsh function based inversion|
|US20070244648 *||Dec 7, 2006||Oct 18, 2007||Baker Hughes Incorporated||Method and computer program product for estimating true intrinsic relaxation time and internal gradient from multigradient nmr logging|
|US20070290684 *||Jul 23, 2007||Dec 20, 2007||Baker Hughes Incorporated||Multiple Echo Train Inversion|
|US20080234937 *||Mar 22, 2007||Sep 25, 2008||Baker Hughes Incorporated||Determination of gas saturation radial profile from multi-frequency nmr data|
|US20090058416 *||Aug 28, 2008||Mar 5, 2009||Baker Hughes Incorporated||Method and Apparatus for NMR Saturation|
|US20090066327 *||Nov 13, 2008||Mar 12, 2009||Baker Hughes Incorporated||Method and computer program product for estimating true intrinsic relaxation time and internal gradient from multigradient nmr logging|
|US20090189604 *||Jul 30, 2009||Baker Hughes Incorporated||Methodology For Interpretation and Analysis of NMR Distributions|
|US20090198446 *||Feb 1, 2008||Aug 6, 2009||Baker Hughes Incorporated||Two dimensional t1/t2app-t2app processing of multi-gradient nmr data|
|US20100088033 *||Oct 3, 2008||Apr 8, 2010||Baker Hughes Incorporated||Data acquisition and processing for invasion profile and gas zone analysis with nmr dual or multiple interecho spacing time logs|
|US20100277167 *||Nov 4, 2010||Baker Hughes Incorporated||Method and Apparatus for Determining Multiscale Similarity Between NMR Measurements and a Reference Well Log|
|US20110187372 *||Aug 4, 2011||Baker Hughes Incorporated||Acoustic Excitation With NMR Pulse|
|US20130113479 *||May 9, 2013||Baker Hughes Incorporated||Method for correcting nmr and nuclear logs in formate mud filtrate invaded formatons|
|WO2011097267A2 *||Feb 2, 2011||Aug 11, 2011||Baker Hughes Incorporated||Acoustic excitation with nmr pulse|
|WO2011097267A3 *||Feb 2, 2011||Nov 17, 2011||Baker Hughes Incorporated||Acoustic excitation with nmr pulse|
|WO2012112254A2 *||Jan 18, 2012||Aug 23, 2012||Baker Hughes Incorporated||Multiphase meter to provide data for production management|
|WO2012112254A3 *||Jan 18, 2012||Oct 26, 2012||Baker Hughes Incorporated||Multiphase meter to provide data for production management|
|International Classification||G01R33/44, G01V11/00, G01V3/32|
|Cooperative Classification||G01V11/00, G01N24/081, G01V3/32|
|European Classification||G01N24/08A, G01V3/32, G01V11/00|
|Nov 15, 1999||AS||Assignment|
Owner name: BAKER HUGHES, INC., TEXAS
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:THEM, HOLGER F.;CHEN, SONGHUA;REEL/FRAME:010418/0254
Effective date: 19991029
|Jul 6, 2005||REMI||Maintenance fee reminder mailed|
|Jul 26, 2005||SULP||Surcharge for late payment|
|Jul 26, 2005||FPAY||Fee payment|
Year of fee payment: 4
|Jun 10, 2009||FPAY||Fee payment|
Year of fee payment: 8
|Mar 8, 2013||FPAY||Fee payment|
Year of fee payment: 12